Process for separating hydrogen sulfide from gaseous mixtures using a hybrid solvent mixture

ABSTRACT

Disclosed is a process for regenerating a hybrid solvent used to remove contaminants from a fluid stream and to provide an improved yield of purified fluid. Said process comprises at least one purification unit ( 12 ) and at least one regeneration unit ( 40 ) wherein condensed water ( 72 ) from the regeneration unit is combined with the regenerated lean hybrid solvent ( 55 ) prior to reuse in the purification unit and none of the condensed water is recycled into the regeneration unit.

FIELD OF THE INVENTION

The present invention relates to a process for regenerating a hybridsolvent used to remove contaminants from a fluid stream and improvingthe yield of the resulting purified stream. Preferably, said fluidstream is a natural gas stream.

BACKGROUND OF THE INVENTION

Fluid streams derived from natural gas reservoirs, petroleum or coal,often contain a significant amount of acid gases, for example carbondioxide, hydrogen sulfide, sulfur dioxide, carbon disulfide, carbonylsulfide, hydrogen cyanide, ammonia, or mercaptans as impurities. Saidfluid streams may be gas, liquid, or mixtures thereof, for example gasessuch as natural gas, refinery gas, hydrocarbon gases from shalepyrolysis, synthesis gas, and the like or liquids such as liquefiedpetroleum gas (LPG) and natural gas liquids (NGL). Various compositionsand processes for removal of acid gas contaminants are known anddescribed in the literature.

Acid gas removal from gas streams, particularly removal of hydrogensulfide and carbon dioxide from gas streams formed in refinery processunits, synthesis gas production plants and oil and gas productionfacilities, is necessary to allow this gas to be used and/or sold intopipeline systems. The removal of sulfur compounds from these acid gasesor “sour gases” is called “sweetening.”

Typically, acid gases are removed using a solvent to remove the acid gasvia the production of a rich solvent. For example, it is well-known totreat such fluid streams with chemical solvents, physical solvents, orcombinations thereof. Chemical solvents such as amine solutions rely ona chemical reaction between the solvent and acid gas contaminants. Theamine usually contacts the acidic gas contaminants in the fluid streamas an aqueous solution containing the amine in an absorber tower withthe aqueous amine solution contacting the fluid stream countercurrently. The regeneration of chemical solvents is achieved by theapplication of heat.

Alternatively, fluid streams may be treated with physical solvents, suchas refrigerated methanol, dialkyl ethers of polyethylene glycols (DEPG),N-methyl-2-pyrrolidones (NMP), propylene carbonate, and the like whichdo not react chemically with the acid gas impurities. Physical solventsdissolve (absorb) the acid gas contaminants from the fluid stream,typically under high pressure. Since no chemical reactions are involved,physical solvent processes usually require less energy than chemicalsolvent processes. While the regeneration of chemical solvents isachieved by the application of heat, physical solvents can be strippedof impurities by reducing the pressure without the application of heat.Physical solvents tend to be favored over chemical solvents when thepartial pressures of acid gases or other impurities are very high.Unlike chemical solvents, physical solvents are non-corrosive, requiringonly carbon steel construction.

Acid gas contaminants are removed by contacting the contaminated productgas with fresh solvent in an absorber or other specialized equipmentoperated under conditions of high pressure and/or low temperature whichare favorable for the type of solvent used. Once the contaminants areremoved, the decontaminated gas is ready for sale, for use, or foradditional downstream conditioning, depending on the product streamspecifications. The solvent is regenerated for reuse by driving off theabsorbed contaminants under low pressure and/or high temperatureconditions favorable for desorption. Flash tanks and/or stripper columnsare typically used to effect this separation.

While numerous prior art processes and systems for acid gas absorptionand solvent regeneration are known in the art, many suffer from one ormore disadvantage or inefficiency. There is an ever-existing desire tofurther improve these technologies, e.g., in respect of purification andenergy consumption.

SUMMARY OF THE INVENTION

An object of the present invention is to improve conventional solventregeneration technology for use in processing fluid streams.

In one embodiment the present invention is a process for treating ahydrocarbon fluid stream containing one or more acid gas, preferably thefluid stream is derived from natural gas and is a gas, a liquid, ormixtures thereof comprising the steps of: i) absorbing one or more acidgas from the hydrocarbon fluid stream in a purification unit by countercurrently contacting the fluid stream with a lean hybrid solventcomprising a chemical solvent, preferably is monoethanolamine,methylethanolamine, monoisopropanolamine, diisopropanolamine,2-hydroxyethylpiperazine, piperazine, 1-methylpiperazine,2-methylpiperazine, 2-(2-aminoethoxy) ethanol;2-(2-tertiarybutylamino)propoxyethanol,2-(2-tertiarybutylamino)ethoxyethanol,2-(2-isopropylamino)propoxyethanol, tertiaryamylaminoethoxyethanol,(1-methyl-2-ethylpropylamino)ethoxyethanol; tris(2-hydroxyethyl)amine(triethanolamine, TEA); tris(2-hydroxypropyl)amine (triisopropanol);tributanolamine; bis(2-hydroxyethyl)methylamine (methyldiethanolamine,MDEA); 2-diethylaminoethanol (diethylethanolamine, DEEA);2-dimethylaminoethanol (dimethylethanolamine, DMEA);3-dimethylamino-1-propanol; 3-diethylamino-1-propanol;2-diisopropylaminoethanol (DIEA); N,N′-bis(2-hydroxypropyl)methylamine(methyldiisopropanolamine, MDIPA); N,N′-bis(2-hydroxyethyl)piperazine(dihydroxyethylpiperazine, DiHEP)); diethanolamine (DEA);2-(tert-butylamino)ethanol; 2-(tert-butylaminoethoxy)ethanol;1-amino-2-methylpropan-2-ol; 2-amino-2-methyl-1-propanol (AMP),2-(2-aminoethoxy)ethanol, and blends thereof; a physical solvent,preferably the physical solvent is dimethyl ether of polyethyleneglycol; propylene carbonate; N-methyl-2-pyrrolidone; methanol;N-acetylmorpholine; N-formylmorpholine;1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; methoxytriglycol;glycerol; sulfolane; ethylene glycol; or blends thereof; and water,preferably from 5 to 40 weight percent water based on the total weightof the hybrid solvent, to produce a purified hydrocarbon fluid streamand a rich hybrid solvent containing hybrid solvent, hydrocarbons, andacid gas(es); ii) passing the rich hybrid solvent to a separation unitto separate hydrocarbons from the rich hybrid solvent providing ahydrocarbon stream and a rich hybrid solvent stream containing acidgas(es) having a low hydrocarbon content; iii) passing the rich hybridsolvent stream containing acid gas(es) with low hydrocarbon content to aregenerating unit to produce a gas stream comprising acid gas(es), watervapor, and residual hybrid solvent and a regenerated lean hybrid solventstream; iv) condensing the gas stream to provide an acid gas stream anda water stream comprising residual acid gases and/or hybrid solvent; v)passing the water stream to a separator to separate residual acidgas(es) providing a water with residual hybrid solvent stream; vi)combining the water with residual hybrid solvent stream and theregenerated lean hybrid solvent stream; and vii) introducing thecombined water with residual hybrid solvent stream and regenerated leanhybrid solvent stream into the purification unit, wherein no portion ofsaid water stream produced in step iv) is introduced back into theregenerating unit.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of a process for treating a fluid streamcomprising a regeneration stage of a known configuration.

FIG. 2 is a schematic of an embodiment of a process for treating a fluidstream of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The invention relates to treatment of fluids to remove acid gases, inwhich the fluid stream is contacted with a hybrid solvent whichpreferentially absorbs the acid gases. More particularly, the inventionis concerned with the regeneration of a hybrid solvent of the typespecified for reuse and maximizing the amount of purified fluid streamproduced.

Fluid streams treatable by the process of the present invention may be agas, a liquid, or mixtures thereof, for example gases produced by agasifier comprising hydrogen, carbon dioxide, and carbon monoxide; asyngas stream comprising hydrogen, carbon dioxide, and carbon monoxide;natural gas; refinery gas; hydrocarbon gases from shale pyrolysis;synthesis gas; and liquids such as liquefied petroleum gas (LPG) andnatural gas liquids (NGL). For example, fluid streams derived fromnatural gas reservoirs, petroleum, or coal, comprise methane (CH₃) andcommonly exist in mixtures with other hydrocarbons, principally ethane(C₂H₆), propane (C₃H₈), butanes (C₄H₁₀), pentanes (C₅H₁₂), and to alesser extent, heavier hydrocarbons. Such fluid streams comprise avariety of impurities such as hydrogen (H₂), water (H₂O), carbonmonoxide (CO), nitrogen (N₂), and acid gases, for example carbon dioxide(CO₂), hydrogen sulfide (H₂S), sulfur dioxide (SO₂), carbon disulfide(CS₂), ammonia (NH₃), hydrogen cyanide (HCN), carbonyl sulfide (COS),and/or mercaptans. In one embodiment, the term “contaminant” refersgenerally to one or more of C₂ or heavier hydrocarbons, impurities, acidgases, and mixtures thereof to be removed from a fluid stream.

The term “hybrid solvent”, as used herein, shall mean a solutioncomprising a combined chemical solvent and physical solvent with somewater, which solutions are capable of absorbing acid gases. Suitablehybrid solvents useful in the process of the present invention mayremove one or more of the above listed contaminants from the fluidstream. Solvents may be non-selective, i.e., remove one or more heavierhydrocarbon/impurity/acid gas or selective, i.e., they may targetspecific heavier hydrocarbons/impurities/acid gas(es).

Preferably, the chemical solvent is one or more amino compound. Suitableamino compounds may be selected from a primary amine, a secondary amine,a tertiary amine, or blends thereof. Alkanolamines are suitable,especially those having 1 to 4 and preferably 2 to 3 carbon atoms peralkanol radical, while dialkanolamines are particularly advantageous.Amino compounds useful in the process of the present invention include,but are not limited to, monoethanolamine, methylethanolamine,monoisopropanolamine, diisopropanolamine, 2-hydroxyethylpiperazine,piperazine, 1-methylpiperazine, 2-methylpiperazine, 2-(2-aminoethoxy)ethanol; 2-(2-tertiarybutylamino)propoxyethanol,2-(2-tertiarybutylamino)ethoxyethanol,2-(2-isopropylamino)propoxyethanol, tertiaryamylaminoethoxyethanol,(1-methyl-2-ethylpropylamino)ethoxyethanol; tris(2-hydroxyethyl)amine(triethanolamine, TEA); tris(2-hydroxypropyl)amine (triisopropanol);tributanolamine; bis(2-hydroxyethyl)methylamine (methyldiethanolamine,MDEA); 2-diethylaminoethanol (diethylethanolamine, DEEA);2-dimethylaminoethanol (dimethylethanolamine, DMEA);3-dimethylamino-1-propanol; 3-diethylamino-1-propanol;2-diisopropylaminoethanol (DIEA); N,N′-bis(2-hydroxypropyl)methylamine(methyldiisopropanolamine, MDIPA); N,N′-bis(2-hydroxyethyl)piperazine(dihydroxyethylpiperazine, DiHEP)); diethanolamine (DEA);2-(tert-butylamino)ethanol; 2-(tert-butylaminoethoxy)ethanol;1-amino-2-methylpropan-2-ol; 2-amino-2-methyl-1-propanol (AMP),2-(2-aminoethoxy)ethanol, and blends thereof.

A hybrid solvent suitable for use in the present invention comprises achemical solvent in an amount of equal to or less than 70 weightpercent, preferably equal to or less than 60 weight percent, morepreferably equal to or less than 50, and more preferably equal to orless than 40 weight percent weight percent based on the total weight ofthe hybrid solvent. Preferably the amount of the chemical solventpresent in the hybrid solvent is an amount of equal to or greater than 5weight percent, more preferably equal to or greater than 10 weightpercent, more preferably equal to or greater than 20, and preferablyequal to or greater than 30 weight percent based on the total weight ofthe hybrid solvent.

Suitable physical solvents include, but are not limited to, one or moreof dimethyl ether of polyethylene glycol (DMPEG), propylene carbonate(PC), N-methyl-2-pyrrolidone (NMP), methanol (MeOH), blends ofN-acetylmorpholine and N-formylmorpholine,1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone (DMTP),methoxytriglycol (MTG), glycerol, sulfolane, ethylene glycol, and blendsthereof.

DMPEG is a mixture of dimethyl ethers of polyethylene glycol(CH₃O(C₂H₄O)_(n)CH₃ (n is from 2 to 9) used in what is referred to asthe SELEXOL™ process to physically absorb H₂S, CO₂, and mercaptans fromgas streams, for example see U.S. Pat. No. 6,203,599 which isincorporated herein in its entirety. Solvents containing DMPEG arelicensed and/or manufactured by several companies including CoastalChemical Company (as COASTAL™ AGR) and Dow (SELEXOL). Other processsuppliers such as Clariant GmbH of Germany offer similar solvents.Clariant solvents are a family of dialkyl ethers of polyethylene glycolunder the GENOSORB™. DMPEG can be used for selective H₂S removal whichrequires stripping, vacuum stripping, or a reboiler.

A hybrid solvent suitable for use in the present invention comprises aphysical solvent in an amount of equal to or less than 70 weightpercent, preferably equal to or less than 60 weight percent, morepreferably equal to or less than 50, and more preferably equal to orless than 40 weight percent based on the total weight of the hybridsolvent. Preferably the amount of the physical solvent present in thehybrid solvent is an amount of equal to or greater than 5 weightpercent, more preferably equal to or greater than 10 weight percent morepreferably equal to or greater than 15 weight percent, and morepreferably equal to or greater than 25 weight percent based on the totalweight of the hybrid solvent.

A hybrid solvent suitable for use in the present invention comprises acondensed stripping solvent, preferably water, that when heated thecondensed stripping solvent vaporizes to become a condensable strippinggas, in the case for water it becomes steam. Preferably the amount ofcondensed stripping gas (in liquid form) is present in the solvent in anamount of equal to or less than 50 weight percent, preferably equal toor less than 40 weight percent, more preferably equal to or less than 30weight percent based on the total weight of the hybrid solvent.Preferably the amount of condensed stripping gas (in liquid form) ispresent in the solvent in an amount of equal to or greater than 5 weightpercent, more preferably equal to or greater than 15 weight percent andmore preferably equal to or greater than 25 weight percent based on thetotal weight of the hybrid solvent.

A conventional solvent process for removing contaminants from a fluidstream is shown in FIG. 1; the solvent regeneration takes place in aregeneration unit, typically a stripper column with a reboiler at thebottom to furnish heat to the solvent. The stripper column is generallya tower designed to create efficient gas/liquid contact containingeither trays or packing. The rich hybrid solvent containing thecontaminants, for example sour gases (such as CO₂ and H₂S) is injectedinto the stripper column typically at or near a location near the topand flows down the tower while a vaporized condensable stripping gas,for example steam, generated in the reboiler flows up the towercountercurrent to the descending rich solvent. The condensable strippinggas aids in “stripping” the contaminants from the rich hybrid solventliquid and sends them back up the tower and out the top of the strippercolumn. The heat added to the stripper reboiler increases thetemperature of the hybrid solvent somewhat, but most of the heat goesinto vaporizing the condensable stripping gas which, in turn, flows intoand up the stripper column. This heat added or inputted into thereboiler must be furnished from an outside source such as steam fromanother process, heat transfer media circulated through the reboiler, ordirectly fired into the reboiler. When contaminants, as gas and/orvapor, pass out the top of the stripper column, a large amount ofcondensable stripping gas also goes out as an admixture with thecontaminants. This overhead condensable stripping gas and gas/vaporstream (called overhead) can be higher in temperature than the feed tothe top of the stripper column. The gases and condensable stripping gaswhich flow from the top of the stripper flow to a condenser (called areflux condenser) where the contaminants are cooled to near ambienttemperatures and most of the condensable stripping gas condenses into acondensed stripper gas, for example water. In the traditional solventunit, this condensed stripper gas is separated via the reflux receiverand is returned near the top of the stripper. Depending on the make-upof the contaminant gases/vapors they may be disposed of, separated,captured, and/or further treated.

FIG. 1 illustrates a conventional fluid stream treatment processincluding a single purification unit 12 in which a solvent is used tocontact and purify the contaminated fluid. In other modes of practice,the purification stage may include a plurality of treatments units inwhich this purifying action takes place. The multiple units may be thesame or different. In other embodiments, membranes may be used inaddition to absorbing units and/or as an alternative to scrubbing units.

In many instances, the contact between the solvent and the contaminatedfluid, such as a hydrocarbon fluid stream, occurs in unit 12 incounter-current fashion as shown in FIG. 1. The lean solvent enters thefirst purification unit 12 at an upper end 14 via inlet 16. After havingabsorbed contaminants from the fluid being treated, the resultant richsolvent exits the first purification unit 12 at a lower end 18 via anoutlet 20. The contaminated fluid moves through unit 12 in the oppositedirection. Via pathway 21, the contaminated fluid stream enters thefirst purification unit 12 at lower end 18 and exits in more pure formfrom upper end 14 via pathway 23. When the purified fluid is a gas, thepurified gas might entrain vaporized solvent, water vapor, or the like.It may be desirable to separate the purified gas from such entrainedcomponents. Consequently, the purified gas may be directed to anoptional condenser (not illustrated in the figure), where the vaporizedsolvent or water vapor exiting the unit 12 is condensed.

As used herein, the term “lean” with respect to a solvent shall meanthat the concentration of contaminants in the solvent is sufficientlylow such that mass transfer of contaminant from the fluid being treatedto the solvent will occur when the solvent and contaminated fluid arecontacted. In one embodiment, a lean solvent includes a regeneratedhybrid solvent solution that has been treated to remove contaminantcontent from a rich hybrid solvent solution, optionally fresh solventintroduced to the system that has not yet been used for purification,and/or a combination of these. In another embodiment, a lean solventincludes a regenerated solvent that has been treated to removecontaminant content from a rich solvent, optionally fresh solventintroduced to the system that has not yet been used for purification,and/or a combination of these. “Fresh solvent” shall refer to a solventthat is being introduced into the treatment system 1 for the first timefrom a suitable source. Fresh solvent also is lean with respect tocontaminants. The term “rich” with respect to a solvent shall refer to asolvent that has picked up contaminants relative to the lean solventduring the course of a purification treatment.

After the rich solvent comprising rich hybrid solvent, low levels ofacid gas(es), and low levels of hydrocarbons exits the firstpurification unit 12, it is desirable to regenerate the solvent so thatthe solvent can be recycled back to the first purification unit 12 formore cycle(s) of treatment. Accordingly, a first pathway 26 is used toconvey the rich solvent to a separation unit, preferably a flash tank28, where depressurization takes place, thereby desorbing a major partof the absorbed hydrocarbons 29. The rich solvent with lower hydrocarboncontent and low levels of acid gas(es) is passed from the flash tank 28via line 30 through a heat exchanger 31 and line 32 then introduced intothe top of a regeneration column, preferably a stripper column 40 wherethe lean solvent is regenerated from the rich solvent. For purposes ofillustration, FIG. 1 shows a regeneration unit that includes as astripper column 40 having a top and a bottom and comprising at least onesection of vapor-liquid contacting device(s) 41, sometimes referred toas stage(s) and a corresponding reboiler 50. In a traditional strippercolumn 40 the rich solvent typically enters towards the top of thecolumn at a location 33 which is equal to or lower than the location ofthe condensed stripper gas return 63 from the reflux receiver 60.

As used herein, and with respect to a column, the terms “upper” and“lower” should be understood as relative to each other. For example,withdrawal or addition of a stream from an upper portion of a columnmeans that the withdrawal or addition is at a higher position (relativeto the ground when the column is in operation) than a stream withdrawnor added from a lower region of the same column. Viewed from anotherperspective, the term upper may thus refer to the upper half of acolumn, whereas the term lower may refer to the lower half of a column.Similarly, where the term “middle” is used, it is to be understood thata middle portion of the column is intermediate to an upper portion and alower portion. However, where upper, middle, and lower are used to referto a column, it should not be understood that such column is strictlydivided into thirds by these terms.

In other embodiments of the prior art and the present invention, thestripper column 40 may comprise as many vapor-liquid contacting sectionsas needed to provide lean solvent, for example as many as 1 to 20sections or more (2 to 20 section not depicted in FIG. 1), in otherwords the stripper column may comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10,11, 12, 13, 14, 15, 16, 17, 18, 19, 20, or more sections. Eachvapor-liquid contacting section may comprise mass transfer devises, suchas packing or trays, to facilitate the desorption of the contaminants.

As used herein, with respect to vapor-liquid contacting sections, theterm portion of a section should be understood to mean that there may bea location within the section wherein some part or fraction of thesection is above that location and some part or fraction of the sectionis below that location.

In other modes of practice of the prior art and the present invention,the first portion of the regeneration stage may include a plurality ofstripper units with at least two sections and/or reboiler units in whichcorresponding regeneration action takes place. The multiple units may bethe same or different. In addition to the stripper column 40, otherkinds of regeneration equipment can be used to help regenerate leansolvent if desired.

As shown in FIG. 1, first pathway 32 is used to convey the rich solventfrom the heat exchanger 31 to the upper portion, at or above the firstsection 41, of stripper column 40 at an inlet position 33. The solventthen is treated in stripper column 40 by contacting the solvent withcondensable stripping gas to heat the solvent. Generally, the solubilityof dissolved contaminants, such as acid gases, tends to decrease as thetemperature of the solvent increases. Thus, heating the solvent with thecondensable stripping gas in the stripper column 40 as the solvent movesfrom the top of the column to the bottom of the column strips awaycontaminants to provide a solvent that is more lean with respect tothese contaminants.

Stripped contaminants exit the top of the stripper column 40 via line 49with the condensable stripper gas (for example steam) as an admixture ofcontaminants, steam, possibly solvent, possibly residual hydrocarbonsand/or acid gas(es). The admixture is directed to a condenser 60. Incondenser 60, solvent, condensed stripper gas (for example condensedwater vapor), and other compounds that may leave the top the strippercolumn 40 together with stripped contaminants are condensed. Thestripped contaminants are discharged from the condenser to line 61 forfurther downstream processing or disposal as desired. At least part ofthe condensed stripping gas, e.g., water vapor, and/or solvent, and/orlow levels of hydrocarbons, and/or residual levels of acid gas(es), andother compounds that may have condensed is returned via line 62 to theupper portion of the stripper column 40 at or above the same location ofthe rich feed at the return position 63 and is used to aid in strippingthe contaminants from the solvent being regenerated.

Solvent leaving the bottom of the stripper column through line 51 passesto a reboiler 50 which is connected back to the stripper column byreturn line 52 and reenters the stripper column at location 53. Thesolvent circulating through the reboiler 50 is heated to produceadditional steam which is feed back into the stripper column 40. Solventwill have an extended residence time in these units 40 and 50 until aportion of the solvent exits reboiler 50 via line 54 through the heatexchanger 31 and back to the purification unit 12.

The hot solvent leaving reboiler 50 via line 54 heats up the solventbeing transported to the stripper column 40 via line 30 in the heatexchanger 31, while the relatively cooler solvent being conveyed to thestripper column 40 in line 31 cools the relatively hot solvent leavingreboiler 50 in line 54. An additional cooling unit 56 may beincorporated into line 55 to further cool the lean solvent prior to thesolvent being introduced to the purification unit 12 via inlet 16.

One of the objects of the process of the present invention is to improvethe efficiency of the regeneration step, specifically the saving ofenergy required for regenerating the hybrid solvent. In one embodimentof the process of the present invention FIG. 2, this is accomplished byeliminating the step of recycling the stripping solvent content, i.e.,the water stream, back into the regeneration column, preferably astripper column 40. In the process of the present invention, the waterwhich is condensed in the condenser 60 is not reintroduced into the topof the stripper column 40 as in the conventional fluid stream treatmentprocess. Reducing the water content means that, at the same temperature,the hybrid solvent has a lower total vapor pressure resulting in a lowertotal pressure for a regeneration step at a fixed temperature. This willcause the partial pressure of the acid component to be further from itsequilibrium value and hence the driving force for mass transfer(stripping) to be greater. However, it will usually not be possible tooperate the regenerator at lower pressure since this is determined bydownstream units. In this case the pressure may be kept the same, and,providing there are no heat transfer constraints, the temperature may beraised. This again is advantageous for the stripping, since at a highertemperature the acid gas is less soluble.

In addition, the reduced proportion of water in the hybrid solventreduces the strength of the chemical bond between the hybrid solvent andthe acid gas, which lowers the resistance of the absorbed gases tostripping

For the invention to make a significant effect on the energy consumptionrequired for regeneration of a hybrid solvent, the hybrid solvent shouldnot contain so much water that its removal from the regeneration zonedoes not substantially alter the thermodynamic and chemical conditionsobtaining there. Some water/steam should, nevertheless, remain in theregenerator as this is necessary for the removal of the acid gases fromthe regenerator. Furthermore, sufficient water should be present in thehybrid solvent that a significant proportion of it can be withdrawn fromthe regenerator without the temperature at the bottom of the regeneratorbecoming unstable due to excessively low partial pressure of theremaining water; a remedy for this phenomenon is, however, proposedbelow.

Referring now to FIG. 2, in the treatment system 10 of the presentinvention, the stripped contaminants exit the top of the stripper column40 via line 49 with the condensable stripper gas (for example steam) asan admixture of contaminants (i.e., low levels of hydrocarbons, acidgas(es) e.g., H₂S, hybrid solvent, or mixtures thereof). The admixtureis directed to a condenser 60. In the condenser 60, hybrid solvent,condensed stripper gas (for example condensed water vapor), and othercompounds that may leave the top of the stripper column 40 together withstripped contaminants are condensed forming a water stream comprisingwater and possibly low levels of hydrocarbons, hybrid solvent, and oracid gas(es). The non-condensed stripped contaminants are dischargedfrom the condenser 60 to line 61 for further downstream processing ordisposal as desired.

In a preferred embodiment of the process of the present invention, noneof the water stream comprising condensed stripping gas, e.g., watervapor and/or solvent and other compounds that may have condensed in thecondenser 60 is returned to the stripper column 40. All or a portion ofthe condensed stripping gas water stream exits the condenser 60 via line62 and is introduced into a separator 70. Examples of suitableseparators 70 are units such as, but not limited to, a heat exchanger ora flash vessel. Residual gaseous components, such as acid gas(es) e.g.,H₂S, and/or any residual hydrocarbons, are separated from the water andany residual hybrid solvent and are discharged from the separatorthrough line 71 for further downstream processing or disposal asdesired. The water and/or solvent stream leaves the separator 70 vialine 72 and is combined with the lean hybrid solvent stream 55 comingfrom the heat exchanger 31. The combined water and solvent stream 73 maypass through an optional heat exchanger 56 before being reintroducedinto the separation column 20 at point 16.

In another embodiment of the process of the present invention (not shownin the figures), a portion of the condensed stripping gas, e.g., watervapor and/or solvent and other compounds that may have condensed in thecondenser 60 is returned to the stripper column 40 and the remainingportion of condensed stripping gas is introduced to a separator 70 vialine 62.

The present invention provides for plant and process to treat a fluidstream which (1) is more energy efficient and/or cost effective bylowering the amount of energy required to produce a lean solvent streamfrom a rich solvent stream and (2) provides a higher yield of thepurified fluid stream.

Examples

Simulation of a Stripping Column with Condenser Feed Modification.

Two different systems are simulated and compared. In Comparative ExampleA, a conventional gas treating process is modeled (e.g., as in FIG. 1).In Example 1, a gas treating process of the present invention is modeled(e.g., FIG. 2). The simulations are performed using Aspen Plus software.The property method used for the fluid phases is the electrolyte NRTLmodel of Chen and coworkers, see Song, Y., Chen, C.-C., 2009, SymmetricElectrolyte Nonrandom Two-Liquid Activity Coefficient Model, Ind. Eng.Chem. Res. 48, 7788-7797. doi:10.1021/ie9004578, Kraats, E. J. van de,Darton, R. C., 1984, Process For Regeneration Of Solvents In HydrogenSulfide Removal From Gases, and U.S. Pat. No. 4,452,763. Modelparameters are developed from pure component and binary vapor-liquidequilibrium data. The absorption and regeneration columns are simulatedusing Aspen's RateSep model, which is a rate-based column model. Themain absorption column has 28 valve trays and operates at 6920 kPa. Theregeneration column has 20 valve trays and operates at 175 kPa. Theassociated condensing unit (60 in FIG. 1 and FIG. 2) temperature is setto 49° C. The rich solvent is fed to the top tray of the regenerationunit at a temperature of 365 K. In the case of the present invention(FIG. 2), the separator 71 is modeled in Aspen Plus with a separatorblock which removes all acid gas contaminants from the condensed waterstream 70 to vapor stream 71 and produces a purified water stream 72which is then combined with the lean solvent stream 55.

The process conditions and composition for the feed gas is shown inTable 1.

TABLE 1 CONDITIONS Flow Rate kmol/s 1.29 Temperature K 305 Pressure kPa6920 COMPOSITION Water Mole fraction 0.0008 CO₂ Mole fraction 0.0555 H₂SMole fraction 0.0393 Methane Mole fraction 0.8213 Ethane Mole fraction0.0527 Propane Mole fraction 0.0208 Butane Mole fraction 0.0093 Methylmercaptan ppmv 119 Ethyl mercaptan ppmv 85 Propyl mercaptan ppmv 27n-Butyl mercaptan ppmv 25

The process conditions and composition for the lean hybrid solvent isshown in Table 2. In Table 2, “MDEA” is methyldiethanolamine, “MTG” ismethoxytriglycol, and “Loading” for a given acid gas species is definedas the ratio of the amount of moles of that species in solution to theamount of moles of alkanolamine in solution. “MTG” is methoxytriglycol.

In Table 3, “mercaptan removal” is defined as the molar percentage ofmercaptans from the feed gas stream that are not recovered in thepurified gas stream. In Comparative Example A and Example 1, thisdifference is between purified gas stream 23 and the feed gas stream 21in FIG. 1 and FIG. 2, respectively.

TABLE 2 CONDITIONS Flow Rate kmol/s 1.22 Temperature K 318 Pressure kPa6950 COMPOSITION Water Mass fraction 0.6846 MDEA Mass fraction 0.1892MTG Mass fraction 0.1261 CO₂ Loading 0.0000 H₂S Loading 0.0002

In the cases of Comparative Example A and Example 1, the processes aredesigned for selectively removing sulfur, and therefore it is desired tomaximize CO₂ slip while removing as much of the sulfur-containingcompounds as possible. In the case of Comparative Example A, and Example1, “Product gas” refers to purified gas stream 23 in FIG. 1 and FIG. 2,respectively.

As shown in Table 3, the simulation of the present invention, Example 1,performed significantly better than the traditional simulation,Comparative Example A. There is a 22% percent reduction in the amount ofenergy required by the reboiler to achieve the same lean IS loading, anda 24% reduction in total duty with only a slight decrease in mercaptanremoval.

TABLE 3 Com. Ex. A Example 1 Total Mercaptan Removal mol % 89 86 CO₂Slip mol % 36 38 CO₂ Concentration in mol % 2.2 2.3 Product Gas H₂SConcentration in ppmv 8.4 10.1 Product Gas Total Mercaptan ppmv 29 36Concentration in Product Gas Reboiler Duty GJ/hr 45 35 Total Duty GJ/hr85 65

What is claimed is:
 1. A process for treating a hydrocarbon fluid streamcontaining one or more acid gas comprising the steps of: i) absorbingone or more acid gas from the hydrocarbon fluid stream in a purificationunit by counter currently contacting the fluid stream with a lean hybridsolvent comprising a chemical solvent, a physical solvent, and water toproduce a purified hydrocarbon fluid stream and a rich hybrid solventcomprising hybrid solvent, hydrocarbons, and acid gas(es); ii) passingthe rich hybrid solvent to a separation unit to separate hydrocarbonsfrom the rich hybrid solvent providing a hydrocarbon stream and a richhybrid solvent stream containing acid gas(es) having a low hydrocarboncontent; iii) passing the rich hybrid solvent stream containing acidgas(es) with low hydrocarbon content to a regenerating unit to produce agas stream comprising acid gas(es), water vapor, and residual hybridsolvent and a regenerated lean hybrid solvent stream; iv) condensing thegas stream to provide an acid gas stream and a water stream comprisingresidual acid gases and/or hybrid solvent; v) passing all or a portionof the water stream to a separator to separate residual acid gas(es)providing a water with residual hybrid solvent stream; vi) combining thewater with residual hybrid solvent stream and the regenerated leanhybrid solvent stream; and vii) introducing the combined water withresidual hybrid solvent stream and regenerated lean hybrid solventstream into the purification unit, wherein no portion of said waterstream produced in step iv) is introduced back into the regeneratingunit.
 2. The process of claim 1 wherein the fluid stream is derived fromnatural gas and is a gas, a liquid, or mixtures thereof.
 3. The processof claim 1 wherein the physical solvent is dimethyl ether ofpolyethylene glycol; propylene carbonate; N-methyl-2-pyrrolidone;methanol; N-acetylmorpholine; N-formylmorpholine;1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; methoxytriglycol;glycerol; sulfolane; ethylene glycol; or blends thereof.
 4. The processof claim 1 wherein the chemical solvent is monoethanolamine,methylethanolamine, monoisopropanolamine, diisopropanolamine,2-hydroxyethylpiperazine, piperazine, 1-methylpiperazine,2-methylpiperazine, 2-(2-aminoethoxy) ethanol;2-(2-tertiarybutylamino)propoxyethanol,2-(2-tertiarybutylamino)ethoxyethanol,2-(2-isopropylamino)propoxyethanol, tertiaryamylaminoethoxyethanol,(1-methyl-2-ethylpropylamino)ethoxyethanol; tris(2-hydroxyethyl)amine(triethanolamine, TEA); tris(2-hydroxypropyl)amine (triisopropanol);tributanolamine; bis(2-hydroxyethyl)methylamine (methyldiethanolamine,MDEA); 2-diethylaminoethanol (diethylethanolamine, DEEA);2-dimethylaminoethanol (dimethylethanolamine, DMEA);3-dimethylamino-1-propanol; 3-diethylamino-1-propanol;2-diisopropylaminoethanol (DIEA); N,N′-bis(2-hydroxypropyl)methylamine(methyldiisopropanolamine, MDIPA); N,N′-bis(2-hydroxyethyl)piperazine(dihydroxyethylpiperazine, DiHEP)); diethanolamine (DEA);2-(tert-butylamino)ethanol; 2-(tert-butylaminoethoxy)ethanol;1-amino-2-methylpropan-2-ol; 2-amino-2-methyl-1-propanol (AMP),2-(2-aminoethoxy)ethanol, and blends thereof.
 5. The process of claim 1wherein the hybrid solvent comprises 5 to 40 weight percent water basedon the total weight of the hybrid solvent.